US3718189A - Consolidation of incompetent formations - Google Patents
Consolidation of incompetent formations Download PDFInfo
- Publication number
- US3718189A US3718189A US3718189DA US3718189A US 3718189 A US3718189 A US 3718189A US 3718189D A US3718189D A US 3718189DA US 3718189 A US3718189 A US 3718189A
- Authority
- US
- United States
- Prior art keywords
- resin
- solution
- catalyst
- formation
- tubing
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Lifetime
Links
- 230000015572 biosynthetic process Effects 0.000 title description 34
- 238000005755 formation reaction Methods 0.000 title description 34
- 238000007596 consolidation process Methods 0.000 title description 16
- 239000003054 catalyst Substances 0.000 abstract description 36
- 239000007788 liquid Substances 0.000 abstract description 36
- 238000002347 injection Methods 0.000 abstract description 20
- 239000007924 injection Substances 0.000 abstract description 20
- 238000000034 method Methods 0.000 abstract description 14
- 239000000243 solution Substances 0.000 description 66
- 229920005989 resin Polymers 0.000 description 63
- 239000011347 resin Substances 0.000 description 63
- 239000012530 fluid Substances 0.000 description 36
- 239000004576 sand Substances 0.000 description 26
- 239000003795 chemical substances by application Substances 0.000 description 17
- 239000000463 material Substances 0.000 description 15
- XPFVYQJUAUNWIW-UHFFFAOYSA-N furfuryl alcohol Chemical compound OCC1=CC=CO1 XPFVYQJUAUNWIW-UHFFFAOYSA-N 0.000 description 13
- -1 hydroxy aryl compound Chemical class 0.000 description 9
- 239000000203 mixture Substances 0.000 description 9
- 239000003921 oil Substances 0.000 description 9
- 229920000647 polyepoxide Polymers 0.000 description 9
- 239000003822 epoxy resin Substances 0.000 description 8
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 6
- ZMANZCXQSJIPKH-UHFFFAOYSA-N Triethylamine Chemical compound CCN(CC)CC ZMANZCXQSJIPKH-UHFFFAOYSA-N 0.000 description 6
- 239000002283 diesel fuel Substances 0.000 description 6
- 239000002245 particle Substances 0.000 description 6
- 239000004848 polyfunctional curative Substances 0.000 description 6
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Chemical compound O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 6
- CSCPPACGZOOCGX-UHFFFAOYSA-N Acetone Chemical compound CC(C)=O CSCPPACGZOOCGX-UHFFFAOYSA-N 0.000 description 5
- LNEPOXFFQSENCJ-UHFFFAOYSA-N haloperidol Chemical compound C1CC(O)(C=2C=CC(Cl)=CC=2)CCN1CCCC(=O)C1=CC=C(F)C=C1 LNEPOXFFQSENCJ-UHFFFAOYSA-N 0.000 description 5
- 239000004593 Epoxy Substances 0.000 description 4
- TWRXJAOTZQYOKJ-UHFFFAOYSA-L Magnesium chloride Chemical compound [Mg+2].[Cl-].[Cl-] TWRXJAOTZQYOKJ-UHFFFAOYSA-L 0.000 description 4
- 238000009825 accumulation Methods 0.000 description 4
- 150000001299 aldehydes Chemical class 0.000 description 4
- IISBACLAFKSPIT-UHFFFAOYSA-N bisphenol A Chemical compound C=1C=C(O)C=CC=1C(C)(C)C1=CC=C(O)C=C1 IISBACLAFKSPIT-UHFFFAOYSA-N 0.000 description 4
- 238000006243 chemical reaction Methods 0.000 description 4
- 235000019441 ethanol Nutrition 0.000 description 4
- ZSIAUFGUXNUGDI-UHFFFAOYSA-N hexan-1-ol Chemical compound CCCCCCO ZSIAUFGUXNUGDI-UHFFFAOYSA-N 0.000 description 4
- 238000004519 manufacturing process Methods 0.000 description 4
- 229920001568 phenolic resin Polymers 0.000 description 4
- 239000012260 resinous material Substances 0.000 description 4
- GHMLBKRAJCXXBS-UHFFFAOYSA-N resorcinol Chemical compound OC1=CC=CC(O)=C1 GHMLBKRAJCXXBS-UHFFFAOYSA-N 0.000 description 4
- 239000007787 solid Substances 0.000 description 4
- ZWEHNKRNPOVVGH-UHFFFAOYSA-N 2-Butanone Chemical compound CCC(C)=O ZWEHNKRNPOVVGH-UHFFFAOYSA-N 0.000 description 3
- POAOYUHQDCAZBD-UHFFFAOYSA-N 2-butoxyethanol Chemical compound CCCCOCCO POAOYUHQDCAZBD-UHFFFAOYSA-N 0.000 description 3
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 description 3
- QIGBRXMKCJKVMJ-UHFFFAOYSA-N Hydroquinone Chemical compound OC1=CC=C(O)C=C1 QIGBRXMKCJKVMJ-UHFFFAOYSA-N 0.000 description 3
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 3
- MUBZPKHOEPUJKR-UHFFFAOYSA-N Oxalic acid Chemical compound OC(=O)C(O)=O MUBZPKHOEPUJKR-UHFFFAOYSA-N 0.000 description 3
- PZPGRFITIJYNEJ-UHFFFAOYSA-N disilane Chemical compound [SiH3][SiH3] PZPGRFITIJYNEJ-UHFFFAOYSA-N 0.000 description 3
- 239000003350 kerosene Substances 0.000 description 3
- 239000011148 porous material Substances 0.000 description 3
- 239000000126 substance Substances 0.000 description 3
- 239000004094 surface-active agent Substances 0.000 description 3
- QTWJRLJHJPIABL-UHFFFAOYSA-N 2-methylphenol;3-methylphenol;4-methylphenol Chemical compound CC1=CC=C(O)C=C1.CC1=CC=CC(O)=C1.CC1=CC=CC=C1O QTWJRLJHJPIABL-UHFFFAOYSA-N 0.000 description 2
- HVBSAKJJOYLTQU-UHFFFAOYSA-N 4-aminobenzenesulfonic acid Chemical compound NC1=CC=C(S(O)(=O)=O)C=C1 HVBSAKJJOYLTQU-UHFFFAOYSA-N 0.000 description 2
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonia chloride Chemical compound [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 description 2
- PAYRUJLWNCNPSJ-UHFFFAOYSA-N Aniline Chemical compound NC1=CC=CC=C1 PAYRUJLWNCNPSJ-UHFFFAOYSA-N 0.000 description 2
- RTZKZFJDLAIYFH-UHFFFAOYSA-N Diethyl ether Chemical compound CCOCC RTZKZFJDLAIYFH-UHFFFAOYSA-N 0.000 description 2
- BRLQWZUYTZBJKN-UHFFFAOYSA-N Epichlorohydrin Chemical compound ClCC1CO1 BRLQWZUYTZBJKN-UHFFFAOYSA-N 0.000 description 2
- QUSNBJAOOMFDIB-UHFFFAOYSA-N Ethylamine Chemical compound CCN QUSNBJAOOMFDIB-UHFFFAOYSA-N 0.000 description 2
- PIICEJLVQHRZGT-UHFFFAOYSA-N Ethylenediamine Chemical compound NCCN PIICEJLVQHRZGT-UHFFFAOYSA-N 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 description 2
- ISWSIDIOOBJBQZ-UHFFFAOYSA-N Phenol Chemical compound OC1=CC=CC=C1 ISWSIDIOOBJBQZ-UHFFFAOYSA-N 0.000 description 2
- NQRYJNQNLNOLGT-UHFFFAOYSA-N Piperidine Chemical compound C1CCNCC1 NQRYJNQNLNOLGT-UHFFFAOYSA-N 0.000 description 2
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 2
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 description 2
- 229920001807 Urea-formaldehyde Polymers 0.000 description 2
- VERMEZLHWFHDLK-UHFFFAOYSA-N benzene-1,2,3,4-tetrol Chemical compound OC1=CC=C(O)C(O)=C1O VERMEZLHWFHDLK-UHFFFAOYSA-N 0.000 description 2
- YCIMNLLNPGFGHC-UHFFFAOYSA-N catechol Chemical compound OC1=CC=CC=C1O YCIMNLLNPGFGHC-UHFFFAOYSA-N 0.000 description 2
- 150000001875 compounds Chemical class 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- FDPIMTJIUBPUKL-UHFFFAOYSA-N dimethylacetone Natural products CCC(=O)CC FDPIMTJIUBPUKL-UHFFFAOYSA-N 0.000 description 2
- SLGWESQGEUXWJQ-UHFFFAOYSA-N formaldehyde;phenol Chemical compound O=C.OC1=CC=CC=C1 SLGWESQGEUXWJQ-UHFFFAOYSA-N 0.000 description 2
- VKYKSIONXSXAKP-UHFFFAOYSA-N hexamethylenetetramine Chemical compound C1N(C2)CN3CN1CN2C3 VKYKSIONXSXAKP-UHFFFAOYSA-N 0.000 description 2
- 229910001629 magnesium chloride Inorganic materials 0.000 description 2
- KPRZOPQOBJRYSW-UHFFFAOYSA-N o-hydroxybenzylamine Natural products NCC1=CC=CC=C1O KPRZOPQOBJRYSW-UHFFFAOYSA-N 0.000 description 2
- 230000035699 permeability Effects 0.000 description 2
- XNGIFLGASWRNHJ-UHFFFAOYSA-N phthalic acid Chemical compound OC(=O)C1=CC=CC=C1C(O)=O XNGIFLGASWRNHJ-UHFFFAOYSA-N 0.000 description 2
- WGYKZJWCGVVSQN-UHFFFAOYSA-N propylamine Chemical compound CCCN WGYKZJWCGVVSQN-UHFFFAOYSA-N 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- CYIDZMCFTVVTJO-UHFFFAOYSA-N pyromellitic acid Chemical compound OC(=O)C1=CC(C(O)=O)=C(C(O)=O)C=C1C(O)=O CYIDZMCFTVVTJO-UHFFFAOYSA-N 0.000 description 2
- 150000003839 salts Chemical class 0.000 description 2
- 229910000077 silane Inorganic materials 0.000 description 2
- 125000006850 spacer group Chemical group 0.000 description 2
- 229940086542 triethylamine Drugs 0.000 description 2
- TXUICONDJPYNPY-UHFFFAOYSA-N (1,10,13-trimethyl-3-oxo-4,5,6,7,8,9,11,12,14,15,16,17-dodecahydrocyclopenta[a]phenanthren-17-yl) heptanoate Chemical compound C1CC2CC(=O)C=C(C)C2(C)C2C1C1CCC(OC(=O)CCCCCC)C1(C)CC2 TXUICONDJPYNPY-UHFFFAOYSA-N 0.000 description 1
- XBTRYWRVOBZSGM-UHFFFAOYSA-N (4-methylphenyl)methanediamine Chemical compound CC1=CC=C(C(N)N)C=C1 XBTRYWRVOBZSGM-UHFFFAOYSA-N 0.000 description 1
- DEWLEGDTCGBNGU-UHFFFAOYSA-N 1,3-dichloropropan-2-ol Chemical compound ClCC(O)CCl DEWLEGDTCGBNGU-UHFFFAOYSA-N 0.000 description 1
- VILCJCGEZXAXTO-UHFFFAOYSA-N 2,2,2-tetramine Chemical compound NCCNCCNCCN VILCJCGEZXAXTO-UHFFFAOYSA-N 0.000 description 1
- ZXCYIJGIGSDJQQ-UHFFFAOYSA-N 2,3-dichloropropan-1-ol Chemical compound OCC(Cl)CCl ZXCYIJGIGSDJQQ-UHFFFAOYSA-N 0.000 description 1
- DUTGJZQZHMMVQK-UHFFFAOYSA-N 2-(trimethoxysilylmethyl)propane-1,3-diamine Chemical compound CO[Si](OC)(OC)CC(CN)CN DUTGJZQZHMMVQK-UHFFFAOYSA-N 0.000 description 1
- JBIJLHTVPXGSAM-UHFFFAOYSA-N 2-naphthylamine Chemical compound C1=CC=CC2=CC(N)=CC=C21 JBIJLHTVPXGSAM-UHFFFAOYSA-N 0.000 description 1
- WVRNUXJQQFPNMN-VAWYXSNFSA-N 3-[(e)-dodec-1-enyl]oxolane-2,5-dione Chemical compound CCCCCCCCCC\C=C\C1CC(=O)OC1=O WVRNUXJQQFPNMN-VAWYXSNFSA-N 0.000 description 1
- ZDZYGYFHTPFREM-UHFFFAOYSA-N 3-[3-aminopropyl(dimethoxy)silyl]oxypropan-1-amine Chemical compound NCCC[Si](OC)(OC)OCCCN ZDZYGYFHTPFREM-UHFFFAOYSA-N 0.000 description 1
- YBRVSVVVWCFQMG-UHFFFAOYSA-N 4,4'-diaminodiphenylmethane Chemical compound C1=CC(N)=CC=C1CC1=CC=C(N)C=C1 YBRVSVVVWCFQMG-UHFFFAOYSA-N 0.000 description 1
- KOGSPLLRMRSADR-UHFFFAOYSA-N 4-(2-aminopropan-2-yl)-1-methylcyclohexan-1-amine Chemical compound CC(C)(N)C1CCC(C)(N)CC1 KOGSPLLRMRSADR-UHFFFAOYSA-N 0.000 description 1
- TVOJMYCLFOSRSO-UHFFFAOYSA-N 4-[3-aminopropyl(dimethoxy)silyl]oxybutan-2-amine Chemical compound NCCC[Si](OC)(OC)OCCC(C)N TVOJMYCLFOSRSO-UHFFFAOYSA-N 0.000 description 1
- ZYZWCJWINLGQRL-UHFFFAOYSA-N 4-phenylcyclohexa-2,4-diene-1,1-diol Chemical group C1=CC(O)(O)CC=C1C1=CC=CC=C1 ZYZWCJWINLGQRL-UHFFFAOYSA-N 0.000 description 1
- VHUUQVKOLVNVRT-UHFFFAOYSA-N Ammonium hydroxide Chemical compound [NH4+].[OH-] VHUUQVKOLVNVRT-UHFFFAOYSA-N 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- RPNUMPOLZDHAAY-UHFFFAOYSA-N Diethylenetriamine Chemical compound NCCNCCN RPNUMPOLZDHAAY-UHFFFAOYSA-N 0.000 description 1
- BLRPTPMANUNPDV-UHFFFAOYSA-N Silane Chemical compound [SiH4] BLRPTPMANUNPDV-UHFFFAOYSA-N 0.000 description 1
- 239000006087 Silane Coupling Agent Substances 0.000 description 1
- QAOWNCQODCNURD-UHFFFAOYSA-N Sulfuric acid Chemical compound OS(O)(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-N 0.000 description 1
- 229910021626 Tin(II) chloride Inorganic materials 0.000 description 1
- XSQUKJJJFZCRTK-UHFFFAOYSA-N Urea Chemical compound NC(N)=O XSQUKJJJFZCRTK-UHFFFAOYSA-N 0.000 description 1
- GTDPSWPPOUPBNX-UHFFFAOYSA-N ac1mqpva Chemical compound CC12C(=O)OC(=O)C1(C)C1(C)C2(C)C(=O)OC1=O GTDPSWPPOUPBNX-UHFFFAOYSA-N 0.000 description 1
- IKHGUXGNUITLKF-XPULMUKRSA-N acetaldehyde Chemical compound [14CH]([14CH3])=O IKHGUXGNUITLKF-XPULMUKRSA-N 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 239000003377 acid catalyst Substances 0.000 description 1
- 230000002378 acidificating effect Effects 0.000 description 1
- 150000001298 alcohols Chemical class 0.000 description 1
- 239000003513 alkali Substances 0.000 description 1
- 150000001336 alkenes Chemical class 0.000 description 1
- 150000005215 alkyl ethers Chemical class 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 235000019270 ammonium chloride Nutrition 0.000 description 1
- 239000000908 ammonium hydroxide Substances 0.000 description 1
- BFNBIHQBYMNNAN-UHFFFAOYSA-N ammonium sulfate Chemical compound N.N.OS(O)(=O)=O BFNBIHQBYMNNAN-UHFFFAOYSA-N 0.000 description 1
- 229910052921 ammonium sulfate Inorganic materials 0.000 description 1
- 235000011130 ammonium sulphate Nutrition 0.000 description 1
- 239000011324 bead Substances 0.000 description 1
- SRSXLGNVWSONIS-UHFFFAOYSA-N benzenesulfonic acid Chemical compound OS(=O)(=O)C1=CC=CC=C1 SRSXLGNVWSONIS-UHFFFAOYSA-N 0.000 description 1
- 229940092714 benzenesulfonic acid Drugs 0.000 description 1
- 239000007767 bonding agent Substances 0.000 description 1
- 239000004202 carbamide Substances 0.000 description 1
- STIAPHVBRDNOAJ-UHFFFAOYSA-N carbamimidoylazanium;carbonate Chemical compound NC(N)=N.NC(N)=N.OC(O)=O STIAPHVBRDNOAJ-UHFFFAOYSA-N 0.000 description 1
- 125000004432 carbon atom Chemical group C* 0.000 description 1
- 239000007795 chemical reaction product Substances 0.000 description 1
- 150000003841 chloride salts Chemical class 0.000 description 1
- 238000009833 condensation Methods 0.000 description 1
- 230000005494 condensation Effects 0.000 description 1
- 229930003836 cresol Natural products 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 230000003111 delayed effect Effects 0.000 description 1
- GYZLOYUZLJXAJU-UHFFFAOYSA-N diglycidyl ether Chemical class C1OC1COCC1CO1 GYZLOYUZLJXAJU-UHFFFAOYSA-N 0.000 description 1
- 125000003700 epoxy group Chemical group 0.000 description 1
- 239000007888 film coating Substances 0.000 description 1
- 238000009501 film coating Methods 0.000 description 1
- 238000011010 flushing procedure Methods 0.000 description 1
- 238000009472 formulation Methods 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 150000002334 glycols Chemical class 0.000 description 1
- 150000003944 halohydrins Chemical class 0.000 description 1
- 239000004312 hexamethylene tetramine Substances 0.000 description 1
- 235000010299 hexamethylene tetramine Nutrition 0.000 description 1
- 235000011167 hydrochloric acid Nutrition 0.000 description 1
- 230000002706 hydrostatic effect Effects 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-M hydroxide Chemical compound [OH-] XLYOFNOQVPJJNP-UHFFFAOYSA-M 0.000 description 1
- 125000005027 hydroxyaryl group Chemical group 0.000 description 1
- 230000003993 interaction Effects 0.000 description 1
- 150000002576 ketones Chemical class 0.000 description 1
- 239000006193 liquid solution Substances 0.000 description 1
- 235000011147 magnesium chloride Nutrition 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- WSFSSNUMVMOOMR-NJFSPNSNSA-N methanone Chemical compound O=[14CH2] WSFSSNUMVMOOMR-NJFSPNSNSA-N 0.000 description 1
- 229960004011 methenamine Drugs 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- QOHMWDJIBGVPIF-UHFFFAOYSA-N n',n'-diethylpropane-1,3-diamine Chemical compound CCN(CC)CCCN QOHMWDJIBGVPIF-UHFFFAOYSA-N 0.000 description 1
- PHQOGHDTIVQXHL-UHFFFAOYSA-N n'-(3-trimethoxysilylpropyl)ethane-1,2-diamine Chemical compound CO[Si](OC)(OC)CCCNCCN PHQOGHDTIVQXHL-UHFFFAOYSA-N 0.000 description 1
- 231100000989 no adverse effect Toxicity 0.000 description 1
- 229920003986 novolac Polymers 0.000 description 1
- 239000003129 oil well Substances 0.000 description 1
- 150000007524 organic acids Chemical class 0.000 description 1
- 235000006408 oxalic acid Nutrition 0.000 description 1
- 238000012856 packing Methods 0.000 description 1
- OXNIZHLAWKMVMX-UHFFFAOYSA-N picric acid Chemical compound OC1=C([N+]([O-])=O)C=C([N+]([O-])=O)C=C1[N+]([O-])=O OXNIZHLAWKMVMX-UHFFFAOYSA-N 0.000 description 1
- 238000006116 polymerization reaction Methods 0.000 description 1
- 150000008442 polyphenolic compounds Polymers 0.000 description 1
- 238000010944 pre-mature reactiony Methods 0.000 description 1
- 230000002028 premature Effects 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 239000000047 product Substances 0.000 description 1
- 230000001737 promoting effect Effects 0.000 description 1
- ROSDSFDQCJNGOL-UHFFFAOYSA-N protonated dimethyl amine Natural products CNC ROSDSFDQCJNGOL-UHFFFAOYSA-N 0.000 description 1
- 239000000376 reactant Substances 0.000 description 1
- 150000004756 silanes Chemical class 0.000 description 1
- 239000002002 slurry Substances 0.000 description 1
- 229910000029 sodium carbonate Inorganic materials 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 239000001119 stannous chloride Substances 0.000 description 1
- 235000011150 stannous chloride Nutrition 0.000 description 1
- 229950000244 sulfanilic acid Drugs 0.000 description 1
- BDHFUVZGWQCTTF-UHFFFAOYSA-N sulfonic acid Chemical compound OS(=O)=O BDHFUVZGWQCTTF-UHFFFAOYSA-N 0.000 description 1
- 239000001117 sulphuric acid Substances 0.000 description 1
- 235000011149 sulphuric acid Nutrition 0.000 description 1
- YNJBWRMUSHSURL-UHFFFAOYSA-N trichloroacetic acid Chemical compound OC(=O)C(Cl)(Cl)Cl YNJBWRMUSHSURL-UHFFFAOYSA-N 0.000 description 1
- 229960001124 trientine Drugs 0.000 description 1
- 229950002929 trinitrophenol Drugs 0.000 description 1
- 150000003739 xylenols Chemical class 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
- E21B33/138—Plastering the borehole wall; Injecting into the formation
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
- Y10T—TECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
- Y10T137/00—Fluid handling
- Y10T137/0318—Processes
- Y10T137/0391—Affecting flow by the addition of material or energy
Definitions
- Field of the invention relates to operations requiring the injection of two or more reactive liquids into a well in sequence and is particularly concerned with the use of resin and catalyst or curing agent solutions for the consolidation of incompetent formations surrounding oil wells, gas wells, and similar boreholes.
- This invention provides an improved method for the injection of two onmgrg mctive materials into a well in sequence whiclf 't leastm part avoids the difficulties referred to above.
- problems due to the accumulation of resin solutions or other reactive liquids on the pipe wall and in the collar recesses during sand consolidations and similar operations can be alleviated by surrounding at least one of the reactive liquids with an annular film or layer of an inert, substantially immiscible liquid of lower viscosity.
- inert li quid will preferably be introduced into the pipe a 'rtlis surface by means of an injector in which parallel flow of a central stream of the reactive material and an annular stream of the inert liquid is established before the streams contact one another.
- injector in which parallel flow of a central stream of the reactive material and an annular stream of the inert liquid is established before the streams contact one another.
- Other methods for introducing the fluids can also be used.
- FIG. 1 in the drawing is a schematic diagram of illus trating apparatus useful in sand consolidation operations carried out in accordance with the invention.
- FIG. 2 is a vertical cross section through an injector which may be employed for purposes of the invention.
- the reaction of these materials to form the resins can be catalyzed by the addition of from about 2% to about 10% by weight, based on the aldehyde-hydroxy aryl compound mixture, of an alkaline catalyst such as guanidine carbonate, aminoquanidine bicarbonate, sodium hydroxide, sodium carbonate, ethyl amine, triethyl amine, aniline, ethylene diamine, or the like.
- an alkaline catalyst such as guanidine carbonate, aminoquanidine bicarbonate, sodium hydroxide, sodium carbonate, ethyl amine, triethyl amine, aniline, ethylene diamine, or the like.
- an acid catalyst such as stannous chloride, magnesium chloride, hydrochloric acid, sulphuric acid, maleic arihydride, picric acid, benzene sulfonic acid, sulfanilic acid, a-naphthylamine sulphonic acid, sodium-l naphthylamine-3,6,8-trisulphonate, or the like can be used.
- an acid catalyst such as stannous chloride, magnesium chloride, hydrochloric acid, sulphuric acid, maleic arihydride, picric acid, benzene sulfonic acid, sulfanilic acid, a-naphthylamine sulphonic acid, sodium-l naphthylamine-3,6,8-trisulphonate, or the like can be used.
- the water-soluble aldehyde, the low molecular weight hydroxy aryl compound, and the catalyst employed for production of the phenol-formaldehyde type resins will normally be utilized in a two-stage procedure.
- the solution injected in the first stage of such a two-stage procedure will generally include all of the reactants except the low molecular weight hydroxy aryl compound.
- the solution injected in the second stage will generally be an oil solu, tion which contains the hydroxy aryl compoud and is substantially immisciblewith the first solution.
- the second solution displaces excess quantities of the first solution from the pore spaces in the formation, and at the same time contributes low molecular weight hydroxy aryl compound to the remaining portion of the first solution to permit reaction of the materials and formation of the resin.
- Epoxy resins can be used for purposes of theinvention in lieu of the aldehyde type resins described above.
- Useful epoxies include the diglycidyl ethers of bisphenol A [bis- (4-hydroxy phenol) dimethyl methane] obtained by the reaction between epichlorohydrin (l-chloro-2,3 epoxy propane) and bisphenol A in the presence of an alkali such as sodium hydroxide or postassium hydroxide.
- Similar resins can be prepared by reacting a mono-nuclear dior trihydroxy phenol such as resorcinol, hydroquinone, pyrocatechol, or chloroglucinol or a polynuclear polyhydroxy phenol such as 4,4-dihydroxy biphenyl with a halohydrin such as 1,2-dichloro-3-hydroxy propane or dichlorohydrin. Still other satisfactory materials include the commercial epoxy resins prepared by the condensation of novolac resins with epichlorohydrin.
- the epoxy resins are employed in conjunction with curing agents or catalysts such as diethylene triamine, ethylene diamine, triethylene tetramine, dirnethylamino propylamine, diethylamino propylamine, piperidine, menthane diamine, triethylamine, benzyldiethylenediethylamino phenol, ditrimethylaminomethylphenol, a-methylbenzyl dimethylamine, meta xylenediamine, 4,4-methylene dianiline, and mixtures of such amines.
- Acidic catalysts such as oxalic acid, phthalic acid, pyromellitic acid, pyrornellitic dianhydride, and dodecenyl succinic anhydride can also be employed.
- the epoxy resins are preferably employed in two-stage operations in which the resin is first dissolved in a solvent such as a mixture of ethyl alcohol, acetone or ethyl ketone with kerosene, diesel oil or white oil containing added aromatics and injected into the formation and a kerosene or similar oil that is substantially free of aromatics and contains a catalyst or curing agent is thereafter injected.
- a solvent such as a mixture of ethyl alcohol, acetone or ethyl ketone with kerosene, diesel oil or white oil containing added aromatics and injected into the formation and a kerosene or similar oil that is substantially free of aromatics and contains a catalyst or curing agent is thereafter injected.
- the latter solution displaces the resin solution from the pore spaces.
- Catalyst or curing agent contained in the second solution is extracted by the resin solution that remains in contact with the sand grains. In the presence of the extracted catalyst or curing agent the resin hard
- furfuryl alcohol resins and the urea formaldehyde resins.
- the furfuryl alcohol formulations are generally utilized by injecting furfuryl alcohol, furfuryl alcohol resin, or a mixture of the alcohol and resin into the formation and thereafter pumping in an oil overflush solution containing a low molecular weight organic acid such as trichloroacetic acid or a delayed acidproducing chemical as a catalyst or curing agent.
- An oil preflush containing a surface active agent is generally used to remove water blocks and render the sand preferentially wet.
- the resin solution usually contains a surfactant and a silane compound designed to improve bonding to the sand grains.
- a diesel oil spacer is normally injected between the resin solution and the catalyst or curing agent solution containing urea, formaldehyde, an accelerator such as ammonium sulfate or ammonium chloride, and a retarder such as ammonium hydroxide or hexamethylene tetramine, into the formation and allowing the material to set.
- an accelerator such as ammonium sulfate or ammonium chloride
- a retarder such as ammonium hydroxide or hexamethylene tetramine
- the resinous materials described above will normally be used in multiple stage processes but in some cases can also be employed in single stage operations. Difliculties due to the accumulation of resin on the pipe wall and in the collar recesses are most pronounced in the multiple stage jobs where the resin is injected first and the catalysts or hardener is later injected but may also be encountered to a lesser extent in operations where the resin and catalyst or hardener are premixed and then injected.
- the well about which the sand is to be consolidated will normally first be killed by pumping in crude oil, diesel fuel, salt water, or a similar fluid through the tubing until suflicient hydrostatic head to overcome the fluid pressure in the formation has been the earths surface.
- the circulation of this fluid should be continued until the sand has been washed out of the wellbore to a level below the perforations.
- this wash-out procedure may be unnecessary and can often be omitted.
- cavities may have been formed in the producing formation behind the casing. These cavities should be filled with sand, gravel, glass beads, metallic shot, or similar particulate solids to prevent subsidence of the formation and damage to the easing. This can be done by suspending the sand, gravel, or other solids in salt water, diesel fuel, or similar fluid by means of a blender located on the earths surface and then injecting the resultant slurry down the well into the perforations. A thickened fluid may be used to transport the solid particles if desired. It is normally preferred to employ particles having size in the range between about 20 mesh and about 4 mesh on the U8. Sieve Series scale.
- Best results are normally obtained by using a material that has been screened so that all the particles fall into a relatively narrow size range. Wide variations in size promote close packing of the particles and result in lower permeability than may be obtained with more uniform particles.
- the size selected will depend in part on the permeability of the formation itself. In general, the use of 10 mesh or larger particles is preferred. Sand or gravel screened to substantially uniform size, 6 to 10 mesh for example, is particularly effective. Excess sand, gravel, or other solids remaining in the wellbore after the cavities have been filled can be removed by the circulation of additional fluid down the tubing and up the annulus between the tubing and casing. A packer can then be set between the tubing and casing to permit the injection of fluids into the formation. Following preparation of the well as described above, the tubing and casing are nor mally filled with diesel oil and injectivity of the formation is checked once this has been done, the consolidation operation can be started.
- FIG. 1 in the drawing is a schematic diagram illustrating surface equipment that may be used in such a sand consolidation operation.
- the apparatus shown includes a preflush tank 10, a resin solution tank 11, an inert liquid tank 12, and a catalyst or hardener solution tank 13. These tanks will normally be mounted on a truck or trailer but in some cases skid mounted units may be used.
- the tanks are manifolded to pump intake line 14 so that fluid can be pumped from them by means of pump 15. Valves 16, 17, 18, and 19 are provided to permit the withdrawal of fluid from individual tanks.
- Line 20 extends from the discharge side of pump 15 to the well 21.
- Tank 12 containing the inert liquid is also-provided with an outlet line 22 containing valve 23.
- This line is connected to the intake side of pump 24, from which discharge line 25 extends to the wellhead.
- the injector shown in FIG. 2 includes an inner sleeve 30 provided with a retaining flange 31 at its upper end.
- the inner wall of this sleeve is tapered near the lower end to form a sharp edge indicated by reference numeral 32.
- the sleeve is slightly tapered near its upper end so that it forms a fluid tight seal with the upper section beloigv flange 31.
- Upper section 33 is connected at its upper end toline 20 from pump 15 and at its lower end is threaded into intermediate housing section 34.
- the intermediate section contains a lateral inlet 36 into which line 25 from pump 24 is connected.
- the intermediate and lower housing sections are concentric with respect to the inner sleeve and form an annular passageway through which fluid introduced from line 25 moves downwardly into tubing string 37.
- the cross sectional area of the annular passageway will normally be between about 2% and about 15% of the cross sectional area of the inner sleeve.
- the outer wall of the sleeve and the inner wall of the lower housing section be smooth and essentially parallel to one another for a distance above the lower end of the sleeve equal to at least one sleeve diameter.
- This type of injector is particularly effective for purposes of the invention but other injectors capable of promoting the formation of an annular stream of one fluid about a central stream of the. other may be used.
- the prefiush contained in tank 10 of FIG. 1 may be any of the fluids conventionally employed for this purpose. These includebriues containing silane coupling agents; aqueous surfactant solutions; low molecular weight alcohols, aldehydes, and ketones such as methanol, acetaldehyde, andv methyl ethyl ketone; and the like.
- Two particularly effective prefiush agents are the aliphatic alcohols containing from 5 to carbon atoms per molecule, particularly n-hexanol, and the alkyl ethers of C to C glycols having at least one C to C alkyl substituent attached to the molecule through an ether linkage, particularly ethylene glycol monobutyl ether. Studies have shown that these agents, when properly used, give results considerably better than those obtained with other preflush materials. The use of ethylene glycol monobutyl ether as a prefiush is particularly effective.
- the resin solution to be used in consolidating the formation is contained in tank 11 of FIG. 1.
- a typical solution may be an acetone solution containing about 60% by volume of a commercial epoxy resin solution such as CIBA Epoxy Resin No. 6005, manufactured by Ciba Products Company, Summit, N.J., and about 0.5% to 1% by volume of a bonding agent such as Dow-Corning Z-6020, a 2-aminoethyl-aminopropyl trimethoxy silane manufactured by the Dow-Corning Corporation, Midland, Mich.
- the epoxy solution used will normally have a viscosity at formation temperature of at least 1 /2 times that of the formation fluids.
- phenolformaldehydes and other resins can also be used.
- the inert liquid used with the epoxy solution is contained in tank 12 of FIG. 1 and will normally be a paraflinic oil having a viscosity lower than that of the resin solution.
- Other inert, low viscosity liquids which are substantially immiscible with the resin solution can also be used.
- the particular inert liquid chosen will depend in part on the particular resin solution employed and may be varied as necessary.
- the catalyst or hardener solution contained in tank 13 of FIG. 1 will also depend upon the particular resin employed.
- a suitable catalyst solution is an acid treated kerosene, diesel oil, or white oil which is essentially free of aromatics and olefins and contains about 1% by volume of tridimethyl aminomethyl phenol or a similar catalyst.
- the yiscosity of the catalyst solution will normally be about twice that of the resin solution.
- the resin and catalyst solutions should be substantially immiscible with one another.
- Z-aminoethyl-aminopropyl-trimethoxy silane Z-aminoethyl-aminopropyl-triethyleneoxide silane, 2-aminomethyl-aminopropyl-trimethoxy silane, 2-aminopropyl-aminopropyl-trimethoxy silane,
- Silanes can also be added to the resin solutions in similar concentrations if desired.
- the prefiush in tank 10 is injected first. This is done by opening valve 16, keeping valves 17, 18, and 19 closed, and then starting pump 15.
- the prefiush discharged from the pump flows through line 20-, sleeve 30, and tubing 37 into the formation. Injection is continued at matrix rates until from about 10 to about gallons of prefiush per foot of formation thickness has been introduced into the well.
- valve 16 is closed and pump 15 is shut down.
- the well may be allowedto stand for several hours.
- n-hexanol and certain otherpreflush agents by allowing the prefiush to stand overnight in the formation before injection of the resin solution is started.
- ethylene glycol monobutyl ether and similar preflushes it is generally advantageous to omit the waiting period and commence injection of the resin-forming materials immediately.
- the use of these and other prefiush agents has been described in the patent literature and will therefore be familiar to those skilled in the art.
- Inert liquid from tank 12 in this case a parafiinic oil of relatively low viscosity
- valve 17 is opened and pump 15 is started.
- Resin solution from tank 11 is pumped through line 20 into the upper end of the injector at the wellhead.
- the stream of resin solution is surrounded by an annular film or layer of the less viscous inert fluid emerging from the annular space between the sleeve and housing. Because the two fluids are substantially immiscible with one another and haye different viscosities, the annular film persists as the fluids move downwardly through the tubing string.
- This l iltn.isolat es the viscous resin solution from the tubing all andprevents its accumulation on the wall and in the collar recesses. It will normally also result in lower friction-losses than would be incurred if the viscous resin solution were injected without the inert liquid. At the lower end of the tubing the fluids emerge into the casing andflow through the perforations into the formation. The presence of the inert. liquid, normally from about 5% to about 25% of the total fluid volume, generally has little or no adverse effect .on the behavior of the resin solution within the formation but may require'the injection of more resin than would otherwise be used.
- the amount of inert fluid entering the perforations can be reduced by unseating the packerabove the unconsolidated zone and withdrawing fluids from the annulus at a controlled rate less than that at which the resin solution and the inert liquid are being introduced into the injector. Because of the density difference between the inert liquid and resin solution and the relatively low injection rates normally used, the two will tend to separate as they emerge from the tubing and hence much of the inert liquid can be recovered at the surface. Injection of the resin solution and inert liquid into the well is continued until suflicient resin to contact the formation for a distance of from 1 to 3 feet or more around the borehole has been introduced. The amount necessary for best results will depend, of course, on the extent to which sand has been washed out behind the casing, on the particular resin solution employed, and on other factors and may be varied as desired. 7
- valve 17 is closed.
- Valve 18 is opened and additional inert liquid is pumped into the well to displace the injected resin solution and serve as a spacer between the resin and catalyst or curing agent solution.
- the volume of inert liquid employed for this purpose should be sufficient to avoid contact between the resin and catalyst or hardener in the tubing due to the mixing which occurs as fluids move down the tubing string.
- the inert liquid used to separate the resin solution from the catalyst or hardener solution to be injected later can be introduced simultaneously through lines 20 and 25 or instead can be injected through line 20 alone. If the latter procedure is used, valve 23 can be closed and pump 24 can be shut down.
- valve 18 is closed and valve 19 is opened.
- Catalyst solution is then pumped from tank 13 into the well through line 20. This fluid moves downwardly through the injector sleeve and tubing, displacing the inert liquid in front of it, and flows through the perforations into the surrounding formation. Because essentially no resin solution remains in the tubing string, residues due to premature reaction between the resin and catalyst are avoided.
- the catalyst solution can also be isolated from the pipe wall with an inert liquid substantially immiscible with it. Within the formation, the catalyst solution displaces resin solution and inert liquid from the pore spaces between the sand grains.
- the resin solution contacting the sand grains is not displaced and instead remains in place as a film coating the sandsurfaces. As the catalyst solution contacts this film, a portion of the catalyst is extracted by the film. This results in hardening of the resin making up the film so that the individual sand grains are cemented together to form a consolidated mass.
- the injection of catalyst solution is continued until sufficient solution to contact essentially all of the resin-coated sand has been introduced. The use of from about 2 to about 10 volumes of catalyst solution per volume of resin solution is generally preferred.
- the well is normally shut in to permit hardening of the resin. The hardening period required depends in part on the reservoir temperature and the effectiveness of the particular catalyst or curing agent employed but in general hardening periods from 8 to about 72 hours are used. Following this, the well can be returned to production.
- a method for the injection of a liquid into a subterranean formation surrounding a well containing a string of tubing and casing which comprises injecting a central stream of said liquid and an annular stream of a less viscous substantially immiscible fluid having a lower density than said liquid down said string of tubing simultaneously while withdrawing fluid at the earths surface from the annular space between said tubing and casing at a rate less than that at which said liquid and inert fluid are injected down said tubing.
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Abstract
A METHOD FOR THE INJECTION OF TWO OR MORE REACTIVE LIQUIDS, A RESIN AND A CATALYST FOR EXAMPLE, INTO A WELL IN SEQUENCE WHEREIN AT LEAST ONE OF THE REACTIVE LIQUIDS IS SURROUNDED BY AN ANNULAR STREAM OF AN INERT, SUBSTANTIALLY IMMISCIBLE LIQUID OF LOWER VISCOSITY AS IT MOVES DOWNWARDLY IN THE WELLBORE.
Description
F 27, 1973 w. M. TERRY 3,718,189
CONSOLIDATION 0F I NCOMPETENT FORMATIONS Filed July 50. 1969 RESIN INERT CATALYST PREFLUSH SOLUTION LIQUID SOLUTION lo M 22 J H2 H3 .l6 I7 23' l8 PUMP PUMP' RESIN SOLUTION INVENTOR. WILLIAM M TERRY ATTORNEY' United States Patent US. Cl. 166-305 1 Claim ABSTRACT OF THE DISCLOSURE A method for the injection of two or more reactive liquids, a resin and a catalyst for example, into a well in sequence wherein at least one of the reactive liquids 1S surrounded by an annular stream of an inert, substantially immiscible liquid of lower viscosity as it moves downwardly in the wellbore.
BACKGROUND OF THE INVENTION (1) Field of the invention This invention relates to operations requiring the injection of two or more reactive liquids into a well in sequence and is particularly concerned with the use of resin and catalyst or curing agent solutions for the consolidation of incompetent formations surrounding oil wells, gas wells, and similar boreholes.
(2) Description of the prior art Methods for the consolidation of incompetent formations surrounding oil and gas Wells frequently involve the injection of a resinous liquid into the formation, the introduction of an inert fluid to displace and distribute the resinous material, and the subsequent injection of a catalyst or curing agent to harden the injected resin and thus bond the sand grains in place. Experience has shown that such methods sometimes present difficulties because of the accumulation of gummy residues that tend to plug the perforations and the face of the producing formation. The residues are apparently formed by interaction of the catalyst or curing agent with small amounts of the resinous material that adhere to the tubing or casing during the initial injection step and are not swept away by the inert flushing agent. The presence of even small amounts of such a residue may interfere with the proper placemerit of the materials and prevent successful consolidation of the incompetent formation. The use of wiper plugs and related devices has not eliminated this problem. Other operations in which reactive chemicals are used present similar difficulties.
SUMMARY OF THE INVENTION This invention provides an improved method for the injection of two onmgrg mctive materials into a well in sequence whiclf 't leastm part avoids the difficulties referred to above. In accordane with the invention, it has now been found that problems due to the accumulation of resin solutions or other reactive liquids on the pipe wall and in the collar recesses during sand consolidations and similar operations can be alleviated by surrounding at least one of the reactive liquids with an annular film or layer of an inert, substantially immiscible liquid of lower viscosity. and inert li quid will preferably be introduced into the pipe a 'rtlis surface by means of an injector in which parallel flow of a central stream of the reactive material and an annular stream of the inert liquid is established before the streams contact one another. Other methods for introducing the fluids can also be used. Under the dynamic conditions existing within the pipe as the fluids move downwardly,
3,718,189 Patented Feb. 27, 1973 ice BRIEF DESCRIPTION OF THE DRAWING FIG. 1 in the drawing is a schematic diagram of illus trating apparatus useful in sand consolidation operations carried out in accordance with the invention. FIG. 2 is a vertical cross section through an injector which may be employed for purposes of the invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS A variety of different resinous materials may be used in sand consolidation operations carried out in accordance with the invention. Phenol-formaldehyde type resins prepared by the reaction of formaldehyde, acetaldehyde, pro-= pionaldehyde or a mixture of water-soluble aldehydes with a low molecular weight hydroxy aryl compound such as phenol, cresol, fi-naphthol, resorcinol, xylenol, cresylic acid or a mixture of such compounds in a weight ratio between about 1:1 and about 9:1 are preferred. The reaction of these materials to form the resins can be catalyzed by the addition of from about 2% to about 10% by weight, based on the aldehyde-hydroxy aryl compound mixture, of an alkaline catalyst such as guanidine carbonate, aminoquanidine bicarbonate, sodium hydroxide, sodium carbonate, ethyl amine, triethyl amine, aniline, ethylene diamine, or the like. From about 0.25% to about 10% by weight, based on the aldehyde-hydroxy aryl compound mixture, of an acid catalyst such as stannous chloride, magnesium chloride, hydrochloric acid, sulphuric acid, maleic arihydride, picric acid, benzene sulfonic acid, sulfanilic acid, a-naphthylamine sulphonic acid, sodium-l naphthylamine-3,6,8-trisulphonate, or the like can be used.
The water-soluble aldehyde, the low molecular weight hydroxy aryl compound, and the catalyst employed for production of the phenol-formaldehyde type resins will normally be utilized in a two-stage procedure. The solution injected in the first stage of such a two-stage procedure will generally include all of the reactants except the low molecular weight hydroxy aryl compound. The solution injected in the second stage will generally be an oil solu, tion which contains the hydroxy aryl compoud and is substantially immisciblewith the first solution. The second solution displaces excess quantities of the first solution from the pore spaces in the formation, and at the same time contributes low molecular weight hydroxy aryl compound to the remaining portion of the first solution to permit reaction of the materials and formation of the resin. The use of phenol-formaldehyde resins and reactive mixtures which produce such resins has been described at length in the patent literature and will be familiar to those skilled in the art.
Epoxy resins can be used for purposes of theinvention in lieu of the aldehyde type resins described above. Useful epoxies include the diglycidyl ethers of bisphenol A [bis- (4-hydroxy phenol) dimethyl methane] obtained by the reaction between epichlorohydrin (l-chloro-2,3 epoxy propane) and bisphenol A in the presence of an alkali such as sodium hydroxide or postassium hydroxide. Similar resins can be prepared by reacting a mono-nuclear dior trihydroxy phenol such as resorcinol, hydroquinone, pyrocatechol, or chloroglucinol or a polynuclear polyhydroxy phenol such as 4,4-dihydroxy biphenyl with a halohydrin such as 1,2-dichloro-3-hydroxy propane or dichlorohydrin. Still other satisfactory materials include the commercial epoxy resins prepared by the condensation of novolac resins with epichlorohydrin.
The epoxy resins are employed in conjunction with curing agents or catalysts such as diethylene triamine, ethylene diamine, triethylene tetramine, dirnethylamino propylamine, diethylamino propylamine, piperidine, menthane diamine, triethylamine, benzyldiethylenediethylamino phenol, ditrimethylaminomethylphenol, a-methylbenzyl dimethylamine, meta xylenediamine, 4,4-methylene dianiline, and mixtures of such amines. Acidic catalysts such as oxalic acid, phthalic acid, pyromellitic acid, pyrornellitic dianhydride, and dodecenyl succinic anhydride can also be employed.
The epoxy resins are preferably employed in two-stage operations in which the resin is first dissolved in a solvent such as a mixture of ethyl alcohol, acetone or ethyl ketone with kerosene, diesel oil or white oil containing added aromatics and injected into the formation and a kerosene or similar oil that is substantially free of aromatics and contains a catalyst or curing agent is thereafter injected. The latter solution displaces the resin solution from the pore spaces. Catalyst or curing agent contained in the second solution is extracted by the resin solution that remains in contact with the sand grains. In the presence of the extracted catalyst or curing agent the resin hardens and bonds the individual sand grains in place. The use of epoxy resins in both single-stage and two-stage sand consolidation processes has been described in the prior art.
Still other resins that may be employed in carrying out the invention include the furfuryl alcohol resins and the urea formaldehyde resins. The furfuryl alcohol formulations are generally utilized by injecting furfuryl alcohol, furfuryl alcohol resin, or a mixture of the alcohol and resin into the formation and thereafter pumping in an oil overflush solution containing a low molecular weight organic acid such as trichloroacetic acid or a delayed acidproducing chemical as a catalyst or curing agent. An oil preflush containing a surface active agent is generally used to remove water blocks and render the sand preferentially wet. The resin solution usually contains a surfactant and a silane compound designed to improve bonding to the sand grains. A diesel oil spacer is normally injected between the resin solution and the catalyst or curing agent solution containing urea, formaldehyde, an accelerator such as ammonium sulfate or ammonium chloride, and a retarder such as ammonium hydroxide or hexamethylene tetramine, into the formation and allowing the material to set. Magnesium chloride or similar chloride salt can be added to facilitate polymerization in carbonate formations. Further details concerning these furfuryl alcohol and urea formaldehyde resins can be found in the literature.
The resinous materials described above will normally be used in multiple stage processes but in some cases can also be employed in single stage operations. Difliculties due to the accumulation of resin on the pipe wall and in the collar recesses are most pronounced in the multiple stage jobs where the resin is injected first and the catalysts or hardener is later injected but may also be encountered to a lesser extent in operations where the resin and catalyst or hardener are premixed and then injected.
In a typical two-stage sand consolidation carried out in accordance with the invention, the well about which the sand is to be consolidated will normally first be killed by pumping in crude oil, diesel fuel, salt water, or a similar fluid through the tubing until suflicient hydrostatic head to overcome the fluid pressure in the formation has been the earths surface. The circulation of this fluid should be continued until the sand has been washed out of the wellbore to a level below the perforations. In new completions where there has been little or no production of fluids and entrained sand, this wash-out procedure may be unnecessary and can often be omitted.
If the well in which the consolidation operation is to be carried out is one from which there has been substantial production of fluids, cavities may have been formed in the producing formation behind the casing. These cavities should be filled with sand, gravel, glass beads, metallic shot, or similar particulate solids to prevent subsidence of the formation and damage to the easing. This can be done by suspending the sand, gravel, or other solids in salt water, diesel fuel, or similar fluid by means of a blender located on the earths surface and then injecting the resultant slurry down the well into the perforations. A thickened fluid may be used to transport the solid particles if desired. It is normally preferred to employ particles having size in the range between about 20 mesh and about 4 mesh on the U8. Sieve Series scale. Best results are normally obtained by using a material that has been screened so that all the particles fall into a relatively narrow size range. Wide variations in size promote close packing of the particles and result in lower permeability than may be obtained with more uniform particles. The size selected will depend in part on the permeability of the formation itself. In general, the use of 10 mesh or larger particles is preferred. Sand or gravel screened to substantially uniform size, 6 to 10 mesh for example, is particularly effective. Excess sand, gravel, or other solids remaining in the wellbore after the cavities have been filled can be removed by the circulation of additional fluid down the tubing and up the annulus between the tubing and casing. A packer can then be set between the tubing and casing to permit the injection of fluids into the formation. Following preparation of the well as described above, the tubing and casing are nor mally filled with diesel oil and injectivity of the formation is checked once this has been done, the consolidation operation can be started.
FIG. 1 in the drawing is a schematic diagram illustrating surface equipment that may be used in such a sand consolidation operation. The apparatus shown includes a preflush tank 10, a resin solution tank 11, an inert liquid tank 12, and a catalyst or hardener solution tank 13. These tanks will normally be mounted on a truck or trailer but in some cases skid mounted units may be used. The tanks are manifolded to pump intake line 14 so that fluid can be pumped from them by means of pump 15. Valves 16, 17, 18, and 19 are provided to permit the withdrawal of fluid from individual tanks. Line 20 extends from the discharge side of pump 15 to the well 21. Tank 12 containing the inert liquid is also-provided with an outlet line 22 containing valve 23. This line is connected to the intake side of pump 24, from which discharge line 25 extends to the wellhead. At the wellhead, the upper end of the tubing string is provided with an injector into which the fluids from lines 20 and 25 are introduced. This injector is shown in vertical cross sec= tion in FIG. 2 of the drawing.
The injector shown in FIG. 2 includes an inner sleeve 30 provided with a retaining flange 31 at its upper end. The inner wall of this sleeve is tapered near the lower end to form a sharp edge indicated by reference numeral 32. A housing consisting of an upper section 33, an interme= diate section 34, and a lower section 35 surrounds the inner sleeve. The sleeve is slightly tapered near its upper end so that it forms a fluid tight seal with the upper section beloigv flange 31. Upper section 33 is connected at its upper end toline 20 from pump 15 and at its lower end is threaded into intermediate housing section 34. The intermediate section contains a lateral inlet 36 into which line 25 from pump 24 is connected. Lower housing sec= tion 35 extends downwardly from the intermediate section and is attached to the upper end of the well tubing 37 above the wellhead. The intermediate and lower housing sections are concentric with respect to the inner sleeve and form an annular passageway through which fluid introduced from line 25 moves downwardly into tubing string 37. The cross sectional area of the annular passageway will normally be between about 2% and about 15% of the cross sectional area of the inner sleeve. It is generally preferred that the outer wall of the sleeve and the inner wall of the lower housing section be smooth and essentially parallel to one another for a distance above the lower end of the sleeve equal to at least one sleeve diameter. This type of injector is particularly effective for purposes of the invention but other injectors capable of promoting the formation of an annular stream of one fluid about a central stream of the. other may be used.
The prefiush contained in tank 10 of FIG. 1 may be any of the fluids conventionally employed for this purpose. These includebriues containing silane coupling agents; aqueous surfactant solutions; low molecular weight alcohols, aldehydes, and ketones such as methanol, acetaldehyde, andv methyl ethyl ketone; and the like. Two particularly effective prefiush agents are the aliphatic alcohols containing from 5 to carbon atoms per molecule, particularly n-hexanol, and the alkyl ethers of C to C glycols having at least one C to C alkyl substituent attached to the molecule through an ether linkage, particularly ethylene glycol monobutyl ether. Studies have shown that these agents, when properly used, give results considerably better than those obtained with other preflush materials. The use of ethylene glycol monobutyl ether as a prefiush is particularly effective.
The resin solution to be used in consolidating the formation is contained in tank 11 of FIG. 1. A typical solution may be an acetone solution containing about 60% by volume of a commercial epoxy resin solution such as CIBA Epoxy Resin No. 6005, manufactured by Ciba Products Company, Summit, N.J., and about 0.5% to 1% by volume of a bonding agent such as Dow-Corning Z-6020, a 2-aminoethyl-aminopropyl trimethoxy silane manufactured by the Dow-Corning Corporation, Midland, Mich. The epoxy solution used will normally have a viscosity at formation temperature of at least 1 /2 times that of the formation fluids. As pointed out above, phenolformaldehydes and other resins can also be used.
The inert liquid used with the epoxy solution is contained in tank 12 of FIG. 1 and will normally be a paraflinic oil having a viscosity lower than that of the resin solution. Other inert, low viscosity liquids which are substantially immiscible with the resin solution can also be used. The particular inert liquid chosen will depend in part on the particular resin solution employed and may be varied as necessary.
The catalyst or hardener solution contained in tank 13 of FIG. 1 will also depend upon the particular resin employed. For the epoxy solution described above, a suitable catalyst solution is an acid treated kerosene, diesel oil, or white oil which is essentially free of aromatics and olefins and contains about 1% by volume of tridimethyl aminomethyl phenol or a similar catalyst. The yiscosity of the catalyst solution will normally be about twice that of the resin solution. The resin and catalyst solutions should be substantially immiscible with one another. As indicated Z-aminoethyl-aminopropyl-trimethoxy silane, Z-aminoethyl-aminopropyl-triethyleneoxide silane, 2-aminomethyl-aminopropyl-trimethoxy silane, 2-aminopropyl-aminopropyl-trimethoxy silane,
6 1-trimethoxy-Z-aminoethyl-Z-aminopropyl disilane, 1-triethyloxide-Z-aminoethyl-2-aminopropyl disilane, 1-trimethoxy-2-aminopropyl-2-aminopropyl disilane, and 1-trimethoxy-2-aminoethyl-2-aminoethyl disilane.
These and similar compounds may be incorporated in the prefiush solutions in concentrations in the range between about 0.1% and about 10% by weight but will preferably be employed between about 0.5% and about 2% by weight. Silanes can also be added to the resin solutions in similar concentrations if desired.
In carrying out the sand consolidation process of the invention, the prefiush in tank 10 is injected first. This is done by opening valve 16, keeping valves 17, 18, and 19 closed, and then starting pump 15. The prefiush discharged from the pump flows through line 20-, sleeve 30, and tubing 37 into the formation. Injection is continued at matrix rates until from about 10 to about gallons of prefiush per foot of formation thickness has been introduced into the well. The optimum amount of prefiush will depend in part on the particular agent selected, the resin to be used, the fluids present in the formation, and other consider= ations and may be varied as necessary. In general, however, from 10 to about 100 gallons per foot will give satisfactory results. Following injection of the prefiush, valve 16 is closed and pump 15 is shut down. Depending on the prefiush selected, the well may be allowedto stand for several hours. Experience has shown that best results are obtained with n-hexanol and certain otherpreflush agents by allowing the prefiush to stand overnight in the formation before injection of the resin solution is started. With ethylene glycol monobutyl ether and similar preflushes, on the other hand, it is generally advantageous to omit the waiting period and commence injection of the resin-forming materials immediately. The use of these and other prefiush agents has been described in the patent literature and will therefore be familiar to those skilled in the art.
After the waiting period, if any, injection of the con= solidating chemicals is commenced. This is done by first opening valve 23 and starting pump 24. Inert liquid from tank 12, in this case a parafiinic oil of relatively low viscosity, is pumped through line 25 into the injector at the top of the tubing string. This fluid flows into the annular space between the inner sleeve 30 and the injector housing 34 and then moves downwardly into the tubing. Fluid remaining in the tubing string from the previous step may be displaced into the formation oi}, if desired, disposed of by unseating the packer and returning it to the surface through the tubing-casing annulus. After sufficient inert fluid to fill the upper part of the tubing string has been injected in this manner, valve 17 is opened and pump 15 is started. Resin solution from tank 11 is pumped through line 20 into the upper end of the injector at the wellhead. At the lower end of the injector, the stream of resin solution is surrounded by an annular film or layer of the less viscous inert fluid emerging from the annular space between the sleeve and housing. Because the two fluids are substantially immiscible with one another and haye different viscosities, the annular film persists as the fluids move downwardly through the tubing string. This l iltn.isolat es the viscous resin solution from the tubing all andprevents its accumulation on the wall and in the collar recesses. It will normally also result in lower friction-losses than would be incurred if the viscous resin solution were injected without the inert liquid. At the lower end of the tubing the fluids emerge into the casing andflow through the perforations into the formation. The presence of the inert. liquid, normally from about 5% to about 25% of the total fluid volume, generally has little or no adverse effect .on the behavior of the resin solution within the formation but may require'the injection of more resin than would otherwise be used. If desired, however, the amount of inert fluid entering the perforations can be reduced by unseating the packerabove the unconsolidated zone and withdrawing fluids from the annulus at a controlled rate less than that at which the resin solution and the inert liquid are being introduced into the injector. Because of the density difference between the inert liquid and resin solution and the relatively low injection rates normally used, the two will tend to separate as they emerge from the tubing and hence much of the inert liquid can be recovered at the surface. Injection of the resin solution and inert liquid into the well is continued until suflicient resin to contact the formation for a distance of from 1 to 3 feet or more around the borehole has been introduced. The amount necessary for best results will depend, of course, on the extent to which sand has been washed out behind the casing, on the particular resin solution employed, and on other factors and may be varied as desired. 7
After the required volume of resin solution has been injected into the well, valve 17 is closed. Valve 18 is opened and additional inert liquid is pumped into the well to displace the injected resin solution and serve as a spacer between the resin and catalyst or curing agent solution. The volume of inert liquid employed for this purpose should be sufficient to avoid contact between the resin and catalyst or hardener in the tubing due to the mixing which occurs as fluids move down the tubing string. The inert liquid used to separate the resin solution from the catalyst or hardener solution to be injected later can be introduced simultaneously through lines 20 and 25 or instead can be injected through line 20 alone. If the latter procedure is used, valve 23 can be closed and pump 24 can be shut down.
Following injection of the required volume of inert liquid into the well behind the resin solution, valve 18 is closed and valve 19 is opened. Catalyst solution is then pumped from tank 13 into the well through line 20. This fluid moves downwardly through the injector sleeve and tubing, displacing the inert liquid in front of it, and flows through the perforations into the surrounding formation. Because essentially no resin solution remains in the tubing string, residues due to premature reaction between the resin and catalyst are avoided. If desired, the catalyst solution can also be isolated from the pipe wall with an inert liquid substantially immiscible with it. Within the formation, the catalyst solution displaces resin solution and inert liquid from the pore spaces between the sand grains. The resin solution contacting the sand grains is not displaced and instead remains in place as a film coating the sandsurfaces. As the catalyst solution contacts this film, a portion of the catalyst is extracted by the film. This results in hardening of the resin making up the film so that the individual sand grains are cemented together to form a consolidated mass. The injection of catalyst solution is continued until sufficient solution to contact essentially all of the resin-coated sand has been introduced. The use of from about 2 to about 10 volumes of catalyst solution per volume of resin solution is generally preferred. After the catalyst solution has been injected, the well is normally shut in to permit hardening of the resin. The hardening period required depends in part on the reservoir temperature and the effectiveness of the particular catalyst or curing agent employed but in general hardening periods from 8 to about 72 hours are used. Following this, the well can be returned to production.
Although the process of the invention has been described above with reference to a sand consolidation operation using an epoxy resin, it will be understood that it can be used with other resins and is applicable in water shu'tofi processes and other operations which also require the injection of two or more reactive materials into a well in sequence. The use of an annular film or layer of inert liquid to surround the reactive material injected initially,-. the later-injected reactive material, or both avoids contactbetween the sequentially injected reactive materials on the wall of the tubing or casing and in the collar recesses. This in turn alleviates problems due to the premature formation of reaction products thus simplifies the use of such materials in sand consolidation, water shutoff, and similar operations.
I claim:
1. A method for the injection of a liquid into a subterranean formation surrounding a well containing a string of tubing and casing which comprises injecting a central stream of said liquid and an annular stream of a less viscous substantially immiscible fluid having a lower density than said liquid down said string of tubing simultaneously while withdrawing fluid at the earths surface from the annular space between said tubing and casing at a rate less than that at which said liquid and inert fluid are injected down said tubing. 1 References Cited UNITED STATES PATENTS MARVIN A. CHAMPION, Primary Examiner I. E. EBEL, Assistant Examiner US. Cl. X.R.
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US84597869A | 1969-07-30 | 1969-07-30 |
Publications (1)
Publication Number | Publication Date |
---|---|
US3718189A true US3718189A (en) | 1973-02-27 |
Family
ID=25296590
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US3718189D Expired - Lifetime US3718189A (en) | 1969-07-30 | 1969-07-30 | Consolidation of incompetent formations |
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US (1) | US3718189A (en) |
Cited By (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3915232A (en) * | 1974-08-27 | 1975-10-28 | Exxon Production Research Co | Method of consolidating incompetent formations |
US4137971A (en) * | 1977-07-08 | 1979-02-06 | Exxon Production Research Company | Method of consolidating a subterranean formation |
US4304301A (en) * | 1980-06-30 | 1981-12-08 | Marathon Oil Company | Process for improving conformance and flow profiles in a subterranean formation |
US4494606A (en) * | 1983-05-19 | 1985-01-22 | Marathon Oil Company | Process for improving vertical conformance in a near well bore environment |
US4983186A (en) * | 1989-07-18 | 1991-01-08 | Petrolite Corporation | Methods and compositions for reduction of drag in hydrocarbon fluids |
US5404951A (en) * | 1993-07-07 | 1995-04-11 | Atlantic Richfield Company | Well treatment with artificial matrix and gel composition |
US7762329B1 (en) * | 2009-01-27 | 2010-07-27 | Halliburton Energy Services, Inc. | Methods for servicing well bores with hardenable resin compositions |
US20100282465A1 (en) * | 2009-05-08 | 2010-11-11 | Halliburton Energy Services, Inc. | Methods of consolidating particulates using a hardenable resin and an orgaosilane coupling agent |
NL2016185A (en) * | 2016-01-29 | 2017-08-02 | Halpa Intellectual Properties B V | Method for counteracting land subsidence in the vicinity of an underground reservoir. |
-
1969
- 1969-07-30 US US3718189D patent/US3718189A/en not_active Expired - Lifetime
Cited By (12)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3915232A (en) * | 1974-08-27 | 1975-10-28 | Exxon Production Research Co | Method of consolidating incompetent formations |
US4137971A (en) * | 1977-07-08 | 1979-02-06 | Exxon Production Research Company | Method of consolidating a subterranean formation |
US4304301A (en) * | 1980-06-30 | 1981-12-08 | Marathon Oil Company | Process for improving conformance and flow profiles in a subterranean formation |
US4494606A (en) * | 1983-05-19 | 1985-01-22 | Marathon Oil Company | Process for improving vertical conformance in a near well bore environment |
US4983186A (en) * | 1989-07-18 | 1991-01-08 | Petrolite Corporation | Methods and compositions for reduction of drag in hydrocarbon fluids |
US5404951A (en) * | 1993-07-07 | 1995-04-11 | Atlantic Richfield Company | Well treatment with artificial matrix and gel composition |
US7762329B1 (en) * | 2009-01-27 | 2010-07-27 | Halliburton Energy Services, Inc. | Methods for servicing well bores with hardenable resin compositions |
US20100186956A1 (en) * | 2009-01-27 | 2010-07-29 | Rickey Lynn Morgan | Methods for Servicing Well Bores with Hardenable Resin Compositions |
US20100282465A1 (en) * | 2009-05-08 | 2010-11-11 | Halliburton Energy Services, Inc. | Methods of consolidating particulates using a hardenable resin and an orgaosilane coupling agent |
NL2016185A (en) * | 2016-01-29 | 2017-08-02 | Halpa Intellectual Properties B V | Method for counteracting land subsidence in the vicinity of an underground reservoir. |
WO2017131520A1 (en) * | 2016-01-29 | 2017-08-03 | Halpa Intellectual Properties B.V. | Method for counteracting land subsidence in the vicinity of an underground reservoir |
US20190040712A1 (en) * | 2016-01-29 | 2019-02-07 | Halpa Intellectual Properties B.V. | Method for counteracting land subsidence in the vicinity of an underground reservoir |
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